1. Technical Field
The present invention relates to method and system for enhancing secondary recovery operations by providing for the efficient removal of solids and other debris from a gas well. More particularly, the present invention provides a method and system by which solids and debris are removed from a gas well bore and surrounding formation by the injection and removal of chemical constituents which results in relieving flow restrictions in well bores and surrounding formation in an economical fashion.
2. Description of Related Art
Oil and natural gas hydrocarbon reservoirs form as a consequence of the transformation of organic matter into various types of hydrocarbon materials, including coals, tars, oils, paraffin waxes and natural gas. It is believed that oil and gas reservoirs form as lighter hydrocarbon molecules percolate toward the surface of the earth until they are trapped in a relatively permeable layer beneath a relatively impermeable layer that ‘caps’ the permeable layer. The lighter hydrocarbon molecules continue accumulating, often accompanied by water molecules, into relatively large sub-surface reservoirs. Since the reservoirs exist at various depths within the earth, they are often under substantial geostatic pressure.
In the last century, natural gas and oil have been extracted by drilling a borehole into the sub-surface geologic formations. In general, most formations were naturally pressurized by the presence of free natural gas that accumulated above the liquid oil layer and, often, by water that accumulated below the liquid oil layer. Since naturally occurring crude oil has a density lower than that of water (i.e., ranging from 0.7 in the case of “light” crude oil to 0.9 in the case of “heavy” crude oil), crude oil accumulates above the water-permeated layer and below the gas-permeated layer of the formation. Thus, a well terminating within the oil-permeated layer would yield oil that receives its drive out energy from an overlying gas-permeated layer and/or an underlying water-permeated layer.
In general, the primary recovery of oil and gas occurs during that period of time that the natural pressurization of a reservoir causes the oil and gas to be driven upwardly through the well bore. At some point in the operating life of the reservoir, the naturally occurring pressurization is effectively depleted. Several different methods, known generally as secondary recovery methods, have been developed to extract oil or natural gas after natural pressurization in the formation is exhausted.
Secondary recovery operations involve re-pressurizing the reservoir with a fluid (i.e., a foreign liquid or a gas) to drive the remaining oil and gas in the permeated layer to the surface through one or more wells. Various fluids, including water at various temperatures, steam, carbon dioxide, and nitrogen, have been used to effect the repressurization of the reservoir and the displacement of the desired crude oil from its rock or sand matrix toward the production wells. The drive fluid is introduced into the reservoir by injection wells which pump the pressurized drive fluid into the reservoir to displace and thereby drive the oil or gas toward and to the producing wells. However, physical blockages and obstacles tend to appear in the formation and well bore as a result of chemical and biological reactions which take place during primary and secondary recovery operations. In turn, these blockages restrict the flow of oil and gas into and up through the well bore.
Historically, gas wells provide positive pressure and expel gas from the well bore into the less pressurized area of the gas gathering system. This positive pressure depends greatly on time of first production and geographical formations in the area. Over a period of time, as gas wells are produced, the flow rates at which gas is recovered decreases and the wells slip below atmospheric pressure, 26–28 inches Hg. At this point in order to recover gas the well must be vacuumed which results in the gas being “sucked” out of the well.
The slowing of production can be due to several factors. One common school of thought is that no gas remains in the well. Another idea is that small particulate matter is clogging the hole that the gas is traveling through to get to the well bore. Many wells have been successfully cleaned and large quantities of gas were found remaining in the well. Current philosophy states that wells become “clogged” with solid particulate matter. For example, a formation maybe likened to a giant sponge. The formation is filled with tiny holes, cracks and fissures similar to the porous nature of a sponge. As we “drag” gas particles from the farthest reaches of the well, they carry small solid particles with them. These particles accumulate in the pores, cracks and fissures of the formation and begin to obstruct the flow of gas through the formation. A positive pressure well has the ability to push these particles out with the gas, but a negative pressure or “vacuum” well leaves the solid particles in the formation.
With the accumulation of this particulate matter, the environment inside the well bore changes. An anaerobic environment is formed as the flow of oil and gas is drawn back out into the formation. Static pressure gradients are formed between the formation and the well bore and then bacterial production occurs. A major product of these bacteria, along with other sources, is hydrogen sulfide gas (H2S), which is an extremely toxic gas, which can pose a major health and safety problem to those working around the well. After years of drawing on a well with vacuum pressure, the rate at which gas can be abstracted from the well becomes greatly diminished.
Currently, the most common practices to remove debris from the well and formation include chemical acid washes, salt-water washes, steam treatments, emulsifying-enzyme agents, bacterial agents and physical stimulation using large sand fraction machinery. By far, the most common practice is to use a strong acid to dissolve the particulate matter residing in the well. While these methods are somewhat effective they leave behind unwanted byproducts such as hydrogen sulfide gas and related precipitates.
In order to clear the well of particulate matter and to induce positive pressure gradients, the standard practice has been to perform an “acid job” on the well. This procedure involves injecting a concentrated acid into the well. There are several inherent problems with acid treatment procedures. Acid will only dissolve particles with similar atomic composition. Although, acid treatment may bring an immediate improvement in gas production, over time the production will slow and decrease below prior production flow rates. Undesirable salt by-products are also formed in acid treatments, since acids have a chemical tendency to produce salts. For example, hydrochloric acid (HCL) will leave behind free chlorine atoms, which will then bond with alkaline metals and other compounds present in the well or formation environment to form a salt. This build up of salt in the well causes the well to become clogged, thereby causing a decrease in production flow rate. Still another drawback with acid jobs is the tendency of acids to produce the toxic gas, H2S. Since sulfur is found abundantly in both its elemental form and in compounds, liberated hydrogen from “acid jobs” can bond with the sulfur to form hydrogen sulfide (H2S) gas. As previously discussed, hydrogen sulfide (H2S) gas poses major health concerns and is considered an extremely hazardous substance for anyone working in the areas where it is present. Acid washing a well is quite expensive and usually not economically feasible in terms of capital expense compared with production returns.
Other common practices in gas well cleaning have included the use of chlorinated solvents. While these solvents are good cleaning agents, they pose major health concerns. Many of the solvents are so toxic that it is not safe for any but the most highly trained workers to handle them. Even if they are selected for use on the well, Class A HAZMAT protection is mandated. A well known and widely used chlorinated solvent, Carbon Tetrachloride (CCL4), has been listed as a known carcinogen and hazardous to human health. These solvents are becoming regulated to such a degree that it makes their use impractical. The cost of procuring chlorinated compounds also makes using many chlorinated solvents impractical and cost prohibitive.
The current existing prior art discloses various methods and systems of remediating well bores. For example, U.S. Pat. No. 4,455,175 (Settineri et. al.) which discloses a method for removing paraffin build up on surfaces in contact with crude oil; U.S. Pat. No. 4,440,229 (Burch) which discloses an oil well servicing process; U.S. Pat. No. 6,196,320 B1 (Ray et. al.) a method of cleaning a well bore prior to installing a water based fluid system; U.S. Pat. No. 5,904,208 (Ray et. al.) a method for cleaning a well bore prior to cementing; U.S. Pat. No. 3,909,422 (Sample, Jr.) a method for removing Elemental Sulfur in sour gas wells; U.S. Pat. No. 3,164,206 (Sharp) a method and product for producing flow in dead wells; U.S. Pat. No. 5,441,927 (Mueller et. al.) fluid drill-hole treatment agents based on polycarbonic acid diesters; U.S. Pat. No. 5,461,028 (Mueller et al.) fluid drill-hole treatment agents based on carbonic acid diesters; U.S. Pat. No. 6,165,946 (Mueller et. al.) process for the facilitated waste disposal of working substances based on water in oil invert emulsions; and, U.S. Pat. No. 4,593,764 (Lilienthal) removal of pipe dope constrictions.
In view of the prior art, a need exists for an effective chemical method of utilizing a chemical solvent combination to efficiently and safely conduct secondary recovery operations on a gas well and the surrounding formation. Likewise, a need exists for conducting secondary recovery operations utilizing a chemical combination of solvating compounds which effectively removes well and formation blockages due to the deposition and build up of sulfur, paraffins, and salt compounds without causing damage to the well or geologic formation environment.